The abbreviation IGCC stands for integrated gasification combined cycle. IGCC power plants are gas and steam turbine power plants (combined cycle (CC) power plants), having a stage for coal gasification connected upstream thereof. During coal gasification, a combustible gas containing carbon monoxide and hydrogen is produced from coal in a gasifier substoichiometrically (λ between approximately 0.2 and 0.4). Meanwhile, it is also possible, as an alternative, to use oil, refinery waste, biomass or waste. The product gas is cleaned and supplied to the gas and steam turbine process. This method allows for a gasifier efficiency of 0.6 and, when utilizing the residual heat, an efficiency of 0.8.
The IGCC process allows the technically simple carbon dioxide separation to be performed prior to the actual combustion process, because physically favorable conditions for separation are present in the form of a high overall pressure, and high concentrations of the gas components CO2 and H2 that are to be separated. In two additional steps, the carbon monoxide developed during the gasification can first be converted into carbon dioxide in a shift stage using steam, and then easily separated given the high pressure, and supplied to final waste disposal. This is a considerable advantage as compared to techniques in which the carbon dioxide must be removed from the flue gas. With atmospheric combustion, the flue gas contains more than 80 percent nitrogen, which is very difficult to remove. The IGCC technology can therefore make a significant contribution to lowering carbon dioxide emissions, and thus to reducing the greenhouse effect caused by humans.
A further advantage of the IGCC is the use of a gas turbine comprising a generator that generates electric power from the combustion of the gas, and the combined use of the waste heat of this gas turbine in a downstream steam turbine. Today, system efficiencies of 50 to 55 percent are possible, which clearly exceed the 40 to 45 percent of a regular coal power plant.
Heretofore, power plants of this design (see FIG. 1 or 2) have been operated in a manner wherein the gas produced during the gasification process (coal gas) is supplied directly as fuel gas to the CC process, after the necessary gas cleaning step. A combined cycle power plant (CCPP) is a power plant in which the principles of a gas turbine power plant and steam power plant are combined. A gas turbine is used as the heat source for a downstream waste heat recovery boiler, which in turn acts as a steam generator for the steam turbine. In this CC process, the coal gas is combusted in the combustion chamber of the gas turbine, and a portion of the energy inherent in the gas is converted into mechanical energy by expansion in a turbine process. The existing perceivable heat is utilized in a subsequent steam turbine process. The concentration of carbon dioxide, CO2, in the flue gas of this process is low. Typically, it is below 10% by volume. The CO2 can be separated from the flue gas using the same method that is possible with today's ordinary steam power plants. It should be noted that the technical difficulty of separating the CO2 increases as the concentration of CO2 in the flue gas decreases. The technical difficulty of separating the CO2 negatively impacts the efficiency of the method.
Separating the coal gas into fuel gas, which contains no, or only a small portion of, the carbon compounds CO (carbon monoxide) and CO2 (carbon dioxide), and a gas flow, which exclusively or predominantly contains CO and CO2, is advantageous for the process of separating the CO2 and conditioning the same for final waste disposal.
One possibility is to use a hydrogen membrane to bring about separation of the hydrogen from modified coal gas that is enriched with hydrogen by way of the shift reaction. This results in a residual gas that, depending on the process, may contain such a high proportion of CO2 that it is possible to optionally liquefy the residual gas, and thereby prepare it for final waste disposal. This goal can be achieved, for example, using a membrane that is exclusively or predominantly permeable by hydrogen.
In one embodiment of this variant (FIG. 3), the membrane is used without further flushing, which is to say that, because of the reduced pressure on the permeate side, the hydrogen diffuses by means of the natural driving force through the membrane. A considerable reduction in pressure is required to ensure that the driving force is also sufficient during the course of the separation process and to achieve a sufficiently high degree of separation of the hydrogen. The disadvantage is that the hydrogen produced in this way first has to be compressed from very low pressures to pressures of approximately 25 bar before it can be supplied to the combustion chamber. This H2 recompression requires tremendous amounts of energy and is a key reason for the major efficiency losses in this process.
If a slightly higher pressure level is selected on the permeate side, so as to minimize the energy expenditure for the H2 recompression, a considerable proportion of the hydrogen will disadvantageously remain in the retentate and not be supplied to the CC process. This hydrogen is either lost entirely for power generation, or can be used, after combustion, with oxygen, which is more complex to produce, only to produce power in a steam power process, the efficiency of which is lower than a CC process. During combustion with air, nitrogen would be introduced and the CO2-rich retentate would become disadvantageously polluted. Göttlicher [1] reports on earlier studies conducted on variants of such a concept.
A further modification of the IGCC process was likewise cited by Göttlicher [1]. Göttlicher also proposes the use of compressed nitrogen as a flushing gas as one possible way to improve the separation of hydrogen. To this end, the nitrogen is obtained from an air separation facility required for the gasification, as is done with the otherwise conventional IGCC process (see FIG. 4). The flushing mass flow of N2 generally approximately corresponds to that of the hydrogen diffused through the membrane.
The flushing gas has thus changed at the outlet from the membrane and is now composed of about one half each of N2 and H2. The H2 partial pressure has risen to a value that is approximately half as high as the overall permeate pressure. The H2 partial pressure on the feed side located directly opposite thereof, at the inlet of the feed into the membrane, is also approximately half the total pressure. This results in a driving force in the membrane that is substantially equal to zero, so that high separation degrees for H2 can, at best, only be achieved with unreasonably large membrane surfaces.
DE 10 2008 011 771 describes a further IGCC power plant comprising H2 membranes, wherein the first flushing gas source, in the form of an air separation facility, is supplemented by a further, stronger flushing gas source. So as to further improve the efficiency, the flue gas can be recirculated from the downstream steam turbine to the combustion chamber of the gas turbine (see FIG. 5). The flue gas recirculation, following stoichiometric air combustion, represents a second possible flushing gas source, which is distinguished by a low oxygen content. For this purpose, a portion of the gas turbine combustion chamber waste gas, which is already under high pressure, is conducted to the permeate side of the membrane. This effect is even better as the content of O2 in the flue gas decreases, because oxygen may react directly with the H2 permeate and would cause an unacceptably high increase in the temperature inside the H2 membrane, for example of several hundred degrees. So as to keep the oxygen content of the waste gas/flue gas as low as possible, generally a substantially stoichiometric ratio of air and fuel (H2 gas) is employed, which is reflected in the parameter λ˜1. In the standard IGCC, hyperstoichiometric air separation is carried out, and thus the large nitrogen-rich flue gas flow generally contains more than 10 mole percent oxygen, and thus is not suited as a flushing gas in this form.
The waste gas from the combustion chamber usually has temperatures above 1200° C., so that the flue gas first has to be cooled before being supplied to the H2 membrane. The high-temperature recuperators required for this are generally expensive and/or are not available and may cause even further energy losses, for example when a final cooler is provided at the end of the hot side of the recuperator, which disadvantageously impacts the energy balance of the overall system.